Thank you for standing by. At this time, I would like to welcome everyone to the Coterra Energy third quarter 2022 earnings conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star one. Thank you. Daniel Guffey, Vice President, Finance, Planning and Analysis, and Investor Relations, you may begin your conference. Thanks, Cheryl, and good morning. Thank you for joining Coterra Energy's third quarter 2022 earnings conference call. Today's prepared remarks will include an overview from Thomas Jorden, CEO and President, and Scott Schroeder, Executive Vice President and CFO. Also on the call, we have Blake Sirgo and Todd Ramer. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers, as well as reconciliations to the most directly comparable GAAP financial measures, were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I'll turn the call over to Tom. Thank you, Dan, and thank you all for joining us today for our third quarter 2022 recap. At third quarter end, Coterra completed our first full year as a new company. We've made remarkable progress and have established a consistent operating rhythm, a spirit of collaboration and teamwork, a commitment to excellence, and a common economic language throughout the company. We've developed new methodologies, learned from one another, and are building a culture of technical excellence, capital discipline, transparency, and open and productive debate. We are deeply proud of the organization and the progress we've made. It all starts in the field. 100% of our assets are in the field, and the top-notch field staff is foundational to an excellent operating company. I wanna give a shout-out and a big thank you to our field personnel, whose perseverance in hostile environments inspires us all. During the past week, I've visited Coterra field offices in Susquehanna, Pennsylvania, Carlsbad, New Mexico, and Oklahoma. It is impossible to spend time in these offices without coming home fired up by the commitment that our field team has to the company and to one another. Their passion for excellence, safety, and environmental stewardship reflects the heartbeat of Coterra. We had a great third quarter. As we announced last night, we reported total production on a BOE basis that was above the high end of our guidance. More importantly, we had excellent economic returns in all three operating basins. Our Permian, Marcellus, and Anadarko business units all posted outstanding economic returns in spite of inflationary headwinds. We reported earnings of $1.51 per share. We declared a fixed plus variable dividend of $0.68 per share, which was an increase over the second quarter. We continued to execute on our buyback with approximately 60% of the authorization now complete, and we retired $874 million of long-term debt. All in, we returned a total of $1 per share during the third quarter in the form of dividends and share repurchases. We have now executed on our return promises for a full year and look forward to making this behavior routine. We are hard at work planning our 2023 capital program. All three of our business units have fielded options that allow us to continue to generate top-tier returns while maintaining flexibility. Although we will not be announcing specifics of our 2023 capital program until our fourth quarter update, we are working on plans that preserve the flexibility to accelerate or decelerate as conditions warrant. We will accomplish this with a mix of rigs and frac crews under both long-term contracts and short-term agreements. Although we're optimistic about 2023 and beyond, we're not good at predicting commodity prices or inflation, and we will be prepared to adapt to changing conditions up or down. As I have said, flexibility is the coin of the realm in the commodity business. A few words about inflation. We currently project total well costs in 2023, increasing 10% to 20% on a dollar per foot basis year-over-year. Individual line items, which include rig rates, frac crews, sand, tubulars, fuel, and labor, may exceed these ranges, but our projected total well costs are a function of our particular timing and particular efficiencies. Although we will continue to fight inflation with efficiencies, longer laterals, and optimal pad designs, we do not have a silver bullet here. We are market takers. The good news is that once we arrive at a total capital number for 2023, we have the asset quality to generate excellent returns in spite of these inflationary headwinds. You will also note that we disclosed some recent flowback data from a nine-well Marcellus development. Seven Upper Marcellus wells and two Lower Marcellus wells. This project also contains three fully bounded infill wells drilled at an 800 ft well spacing, allowing us the opportunity to study well-to-well interference. We also studied communication between the Upper and the Lower Marcellus. There were 11 existing Lower Marcellus wells underlying this project and offsetting the new Upper Marcellus wells. Those wells have cum a total of 127 Bcf, coming online between 2012 and 2019. That was preexisting production in the lower Marcellus under these new upper Marcellus wells. We're pleased to announce that we see little to no communication between the upper and lower Marcellus wells, confirming our thesis that the Purcell Limestone that separates them serves as an effective frac barrier. This will be very important to our future development of the upper Marcellus. Plus, owing to the lower dollar per foot cost of the upper Marcellus wells, the economic returns of the lower and upper Marcellus are comparable at a flat $4.25 NYMEX gas price. We will continue to delineate the upper Marcellus and seek to enhance further capital efficiencies by optimizing spacing and completion parameters. We are very encouraged with the economic learnings from this important test. Finally, let me comment on the Marcellus reserve revision that we discussed in our release. This was a culmination of bringing the teams together from both legacy companies, establishing technical consistency, and applying learnings from across Coterra's three basins. These expected revisions are spread over the 50-year life of producing wells. For new wells, the difference between our revised forecast parameters and the original forecast parameters have minor differences within the first five years of production when 80% of the net present value of a new well is captured. Furthermore, these expected revisions will have no material impact on our near-term cash flow, capital allocation, or ability to deliver on the return of capital promises that we have made. I also want to highlight that last night we released our first Coterra Sustainability Report, which can be found on our website. We hope that you will find it to be readable, crisp, and factual. It reflects our commitment to be the very best and to communicate with authenticity and integrity. With that, I will turn the call over to Scott, who will recap a great quarter. Thanks, Tom. Today, I will briefly touch on third quarter 2022 results, shareholder returns, and then finish with updated guidance. During the quarter, Coterra generated discretionary cash flow of $1.5 billion, which was up 2% quarter-over-quarter, driven by strong operational execution and robust natural gas prices. Accrued third quarter capital expenditures totaled $456 million, down 3% sequentially. Coterra's free cash flow totaled $1.1 billion for the quarter, which included cash hedge losses totaling $259 million. Third quarter 2022 total production volumes averaged 641 MBOE per day, with natural gas volumes averaging 2.81 Bcf per day. BOE and natural gas production were above the high end of guidance. Oil volumes averaged 87.9 MBO per day, above the midpoint of expectations. The strong third quarter 2022 volume performance was driven by a combination of accelerated cycle times, positive well productivity, and the result of being in ethane recovery for the majority of the quarter. Third quarter turn-in-lines totaled 46 net wells in line with expectations. During the third quarter, the company retired a total of $830 million of long-term notes, which is a combination of the previously announced $124 million of private notes and $706 million of 2024 public notes. After the quarter closed, the company retired the remaining portion of the 2024 notes, which totaled an incremental $44 million. The company exited the quarter with $778 million of cash, a net debt to trailing 12-month EBITDAX leverage ratio of 0.2 times, and liquidity standing at $2.3 billion. We've been clear about our desire to reduce absolute debt levels, and the third quarter actions achieved our targeted level. Turning to return of capital. October 1, 2022, as Tom said, was the one-year anniversary of Coterra. If you recall, on the merger date, we guided that Coterra had the potential to generate $4.7 billion in cumulative free cash flow for the period of 2022 through 2024 at mid-cycle prices. Driven by strong operational performance and higher commodity prices, Coterra is expected to generate close to $4 billion in free cash flow in 2022 alone. Since our formation, and including yesterday's announced dividends, the company will have returned $4.3 billion to shareholders or 18% of our current market cap in its first 14 months. This includes $2.6 billion in cash dividends made up of $583 million in base dividends, $407 million in special dividend upon the transaction being closed, and $1.7 billion in variable dividends. Also included in that number is $740 million in share repurchases and $874 million in debt repayment. We will continue to follow through on our commitment to a disciplined capital allocation and return strategy. For the most recent quarter, we announced shareholder returns totaling 74% of the third quarter 2022 free cash flow or 44% of cash flow from operations. The return of capital is being delivered through three methods. First, we maintained our $0.15 per share common dividend, which remains one of the largest base dividend yields in the industry. Second, we announced a variable dividend of $0.53 per share. Combined with our base plus variable dividends that total $0.68 per share, up from $0.65 per share paid in the second quarter. Our total cash dividend is equal to 50% of free cash flow, as is our continuing commitment. Third, during the third quarter, we repurchased $253 million of common stock, or 9.3 million shares at an average price of $27.03. The buyback amounted to $0.32 per share or 24% of our free cash flow. Just over seven months since announcing our $1.2 billion buyback authorization, we have repurchased 28 million shares for $740 million, utilizing 59% of our authorization. We previously discussed our intention to execute the full authorization within a year and remain on track. Lastly, I will discuss guidance. We modestly increased our full-year 2022 BOE and natural gas production guidance while maintaining capital and unit cost guidance. Our annual production guidance is up 1% to 625 BOE to 640 BOE per day and 2.78 Bcf to 2.85 Bcf per day, respectively. We have no change to our 2022 turn-in-line guidance and expect total company turn-in-lines to be near the midpoint of guidance. Our fourth quarter total production guidance is 615 to 635 MBOE per day with natural gas and oil volume guidance set at 2.73 to 2.78 Bcf per day and 86 to 89 MBO per day, respectively. On the 2022 capital, we are maintaining our guidance range but expect to be at the high end, driven by ongoing inflation. While we are continuing to see inflationary pressures relating to operating costs, we are maintaining unit cost guidance for LOE, GP&T, G&A, taxes other than income, and deferred tax ratio. One note, the deferred tax ratio during the third quarter of 8% was below the expected run rate due to a favorable tax law change in Pennsylvania that was enacted during the quarter. The Pennsylvania corporate income tax rate was lowered for all future years, reducing Coterra's future tax liability. This reversal was recognized as a deferred tax gain on the quarter, which caused a one-time adjustment and drove the deferred tax ratio below our annual guidance. As it relates to the reserve news and its impact, the third quarter results reflect the increased DD&A required after the adjustment. This will carry through into the fourth quarter and even with the adjustments, our full-year DD&A guidance remains unchanged. In summary, Coterra continues to deliver on all fronts with strong operational execution and disciplined capital allocation. As always, maintaining one of the best balance sheets in the industry remains foundational to our future success. With that, we'll turn it back over to the operator for Q&A. To ask a question, please press star one. Please limit yourself to one question and one follow-up. Your first question is from Jeanine Wai of Barclays. Please go ahead. Your line is open. Hi. Good morning, everyone. Thanks for taking our questions. Hi, Jeanine. Hi. Good morning, Tom. Our first question is on capital allocation. I guess with the Upper Marcellus now looking like it's comparing more favorably to the Lower than maybe what perhaps some may have appreciated, and the Permian looks like it's firing on all cylinders, there seems to be a lot of optionality for capital allocation next year. Do you have any further commentary on what that allocation could look like between the Upper and Lower going forward? And also perhaps any commentary on what it could look like between your three basins next year? Well, thank you for that question, Jeanine. You know, we don't have any specifics. I will say your observation is spot on. We're very pleased by the Upper, and we're also pleased by the economics of the Upper. You know, as we look at the Marcellus, you know, there are a lot of factors that come into play. One is, you know, we are kind of finishing out that Lower, and our choices of pads is also a function of our system line pressure, where we have compression capability. I think you'll see us have a sizeable mix of Upper in our portfolio going forward. Sizeable is somewhere 30% to 40%, but we're still working on that. You know, we would like to continue to delineate, but thus far we're pretty encouraged, as you can see. You also rightly noted our Permian is firing on all cylinders. You know, right now we have a lot of options in front of us for 2023. We've got some outstanding economic returns. We'll Look forward to continuing to work it, but, yeah, we don't really have anything definitive to say this morning on how we're gonna allocate capital. Okay, great. You knew we had to try. Thank you. Our second question, maybe moving to the reserves. On the reserves update, the Permian Anadarko reserves are expected to increase by about 10% year-over-year, and the Marcellus is expected to decrease by about a third. On the Marcellus, the deal closed a little over a year ago. Is this change really just a matter of having maybe more time under your belt to study the asset, and that's what's driving the updated view on the type curves? Or is it something more related to, like, your tangent philosophy or your price deck assumption? Any additional color would be great on where you're seeing the most impact along the performance curve. We heard your prepared remarks that 80% of the NPV value is within the first five years. A lot of questions in there, but you know, just an important topic. Thank you. Yeah, no, thank you for that, Jeanine. You know, when you bring two teams together, there's lots of differences. There's differences in operating techniques, differences in safety philosophy. There are differences in incentive systems. There's differences in technical analysis. You know, we really set to work October 1, 2021, of just reconciling a lot of these differences. You know, we brought some new techniques and technologies. We learned from one another. I will say, you know, one of the things you've heard me talk about in the past is this annual look back we do. It really wasn't until the third quarter that we were able to look at the kind of systemic issue of the reserves in a light that was, I think, new to many of our colleagues that had worked the Marcellus for a long time. It really was third quarter when we said, "Okay, you know, this is worth digging into." We had all the experts in the room. Janine, I really wanna say and hopefully this came out from our remarks, we really see this as having little to modest financial impact. In fact, we're saying it's not a material event. There's certainly no impairment involved in with it, and the DD&A is extremely modest. We also don't see it really impacting our cash flow significantly over, you know, the next three to five years. Now, you may say, "Well, how do you say that?" Well, you know, you cannot take reserve forecasts and just immediately translate it into a cash flow forecast. The reason is that field in Susquehanna County is very complex. You have line pressure issues. You have parent-child effects. You have occasional shut-ins that you have to deal with. What happens is our team in Pittsburgh takes the projects they're gonna drill, and they take it into a system-wide model and see what it's gonna generate in terms of a production forecast. Although that starts with a base reserve forecast, you do look at all the various things that are gonna impact that. Those reserves are gonna be produced over a 50-year timeframe. Over a three, five, 10-year timeframe, the actual production, actual cash flow is gonna be based on particulars of the field hydraulics and field situation. For many, many years, and certainly for Coterra's history, our cash flow forecasts have come from that field level analysis and the actual operating conditions on the ground. We don't see this as having a material impact to our cash flow forecast over the next three to five years. Now, you know, in fairness to your question, over that 50-year life, that gap is gonna be closed, but that differential is decades out in the future in the well life. This is not a significant impact on our cash flow as we go forward. Certainly won't impact our capital allocation. You know, we did the analysis in the third quarter, and we felt like, okay, we saw it. At least we could define ranges with certain confidence, and we thought it was our responsibility to communicate it, and that's why we came out strong. We appreciate all the details. Thank you, Tom. Your next question is from Umang Choudhary of Goldman Sachs. Please go ahead. Your line is open. Hi. Good morning, and thank you for taking my questions. I wanted to circle back on the activity point which you mentioned. I understand it's early days, but wanted to get your thoughts on the Permian and the gas basis risks next year and how you're thinking about managing that risk and if that would bias your activity towards oilier areas in the Permian Basin. Well, that's a great question, and I'll invite Blake Sirgo here to join me in the answer. You know, one of the things we look at very carefully. Now, obviously, in the Permian Basin, oil is our dominant revenue. In fact, part of the problem in the Permian Basin is gas is kind of a byproduct, and oil is such a dominant part of the revenue that, you know, it's associated gas, but the drilling decisions are really driven by that oil. We've taken great pains over the years, and our marketing group, and Blake can comment on this, has been very effective in giving us assuredness of flow. Waha pricing is a very small exposure to our overall corporate price structure, but the critical issue is we feel very confident saying that we have assuredness of flow, and regardless of that basis, we think our wells will flow, and we'll be able to capture that oil revenue, which is really foundational to the investment decision. Blake, I'll let you comment on that. Yeah. Thanks, Tom. I think we all saw Waha go negative late last week, which, of course, we don't like seeing any of the commodities we worked so hard to produce go negative. October still finished above $3 for the month. Historically, that's really strong for Waha. It's not a surprise. Waha's really tight. Capacity is gonna be tight until the end of 2023, when the expansion projects come online. Any time there's major planned maintenance events like this, we're gonna see these fluctuations. Tom just, you know, alluded to it. While Waha-priced gas is 60% of our Permian gas portfolio, it's only 6% of our Coterra gas portfolio. We have layered in some Waha hedges going into 2023 to help minimize that volatility in cash flow. Really, all we're focused on is flow assurance, as Tom said. All our Waha price sales are firm with great counterparties. That was on display last week when we were briefly up a day offline in the Permian, and we had absolutely no interruption to flow. While we expect some blips along the way throughout 2023, it's. We view it as minimal impact to cash flow, and we have the flow assurance we need. Great. Thank you. My next question was on inflation, expectations for next year. I know it's early days. You talked about 10% to 20% increase potentially in 2023. Are you seeing any regional differences between Permian and Appalachia, and especially in the Perm, because I believe last quarter you had talked about cost increasing by 30% to 35% over 2021 in 2022? Yeah, sure. This is Blake. I'll comment on that. We see inflation, you know, widely in every basin in all the same categories. We just went through this process, contracting a lot of our services for 2023. I'd say in general, the Marcellus is a little higher. That's not unique to just this moment in time. Everything in the Marcellus is winterized, so it commands a little higher price, and it's just a smaller swimming pool than the Permian, so there's a little less competition for services, and that comes out in more inflation. When we look ahead to 2023, you know, right now we're saying 10% to 20% is what we're seeing, and that's based on the most recent contracts we're entering into. We do have some cost categories, though, that are beyond that range. The reason we're not projecting beyond that is there's a lot of things that go into our $23 per foot. Lateral length, timing, 2022 contracts extending into 2023, our efficiencies, all those things come into play. Right now we're modeling closer to the lower end of that range. If inflation runs through 2023 like it did in 2022, we could easily see the high end of that range. Until then, we'll focus on what we can control. Makes sense. Your next question is from Arun Jayaram of J.P. Morgan. Please go ahead. Your line is open. Yeah. Good morning. Tom, I was wondering if I could maybe ask the question on the reserve write-down maybe a different way. If you did the PV-10 standardized measure kind of at a flat deck, is there any way you can give us a sense of what the impact would be? 'Cause it sounds like a lot of the impacts is in the later portion of the production life of the wells. Just wanted to get a sense of maybe you could haircut it like that. You know, Arun, you know, what I can tell you is in something like this, the value impact is significantly less than the volume impact. I think that's probably clear to everybody. You know, I just wanna say, although we've come out and we've really tried to give ranges that we think are going to be, you know, we think they're realistic, this is really a fourth quarter process. We wanna finish our reserves. You know, we've got an auditor that we, you know, we'd like to get their reserve audit. We have a lot of remaining work to finish that out. You know, if I could indulge you to hold that question till we're finished in the fourth quarter, I think we can be pretty forthcoming. You know, we think the ranges we've given are realistic and you know, we're kinda coming out a quarter early on reserve talk. Understood. Tom, you mentioned that the cash flow impact would be minimal. Could you give us a sense of what kind of impact do you sense on your, you know, your production outlook in view of sustaining capital requirements, you know, in the Marcellus? Does this have any impact as you think about, you know, 2023 or 2024 production? I don't think that this has any impact on it. Now I will say, you know, it depends whether you're talking about the upper or lower. I mean, as we're finishing out the lower, as we've talked in the past, we're dealing with situations where we may have shorter lateral lengths. You know, we have up space, but, you know, we are infilling islands of undrilled, so we have some constraints. That will inevitably probably lead to a slight decrease in capital efficiency over what we're all used to. That's just kinda the nature of the beast. We think it's most prudent within the field because of our infrastructure requirements to go ahead and, you know. As we continue to poke around in the upper, we're gonna finish out that lower. You know, we don't see the issue on reserves having any material effect on that issue at all. All right, great. Thanks a lot. Your next question is from Neal Dingmann of Truist Securities. Please go ahead. Your line is open. Morning, Neal. Can you hear me fine? Loud and clear, Neal. All right. My first question just on the Marcellus specifically. Love some of the Upper Marcellus news that you have put out and some of those results. I'm just wondering, going forward, two questions around that. One, how active would you be able to co-develop in those areas between the Upper and Lower? Right now, the opportunity where you've had some of those stellar Lower Marcellus wells, is there opportunities to go back and go after some upper? Well, our team is looking at that right now. You know, we've challenged them, you know, I may contradict my answer to the last question. You know, we're filling out the lower, but we've challenged them to really look at that infrastructure and let's just try to break the mold and do it in the most profitable way. You know, always we like to rank our opportunities and do the best first and work our way down the ladder there on economic value. You know, it's a complex function of infrastructure, compression availability, and you know, we're gonna try to be active on our best opportunities. I appreciate your comments. We're really quite pleased with what we're seeing out of the upper. We're gonna try to fit as much of that in as we can. You know, you just have to kind of wait until we announce our 2023 program. We've got some really bright people working on the best economic model they can field. No, love to hear it. Thanks, Tom. Just secondly, on inventory, Tom, do you find yourself now with this Upper Marcellus success and with that and obviously with the Del and MidCon, feeling that you have more than ample acreage? Or just everybody sort of asked the M&A question. I guess my way to tackle that is how actively are you looking at, you know, sort of the plays and assets being thrown out there? Or are you pretty content given the size now of inventory you have after this Upper Marcellus success? Boy, you know, Neal, I'm an explorationist at heart. Words like ample acreage and content just don't sit well with me. You know, look, we've got a very deep inventory in all of our basins. In fact, I was reviewing that in some detail this morning. We're very pleased with our inventory, but, you know, we're also pretty high on Coterra's ability to be an outstanding operator. You know, I mentioned our field staff, I mentioned our outstanding scientists throughout this organization. If we had the opportunity to acquire more assets at an entry price that added value for the Coterra shareholder, we would do it. We look at everything. We are highly curious as an organization and yeah, but we're just not gonna try to play financial games with that. It's gonna have to be something that adds real sustainable value over cycles. You know, it's my hope and intent that we're gonna find something. Great. Yeah. Thanks, Tom. Let me just finish by saying it's not. Yes, sir. It's not a goal. It's an ongoing kind of wish. We don't lay down markers on an annual basis and say, "Let's go buy something." I mean, that's kind of a dangerous way to manage. We want to be opportunistic. Agree. Thanks for the details. Your next question is from Derrick Whitfield at Stifel. Please go ahead. Your line is open. Good morning, all, and thanks for taking my questions. Hi, Derrick. Tom, I wanted to lead with the question on your broader outlook. While acknowledging you're not offering formal 2023 guidance today. Mm-hmm Could I ask you to comment on your high level takeaways from the CapEx proposals you've received from your three business units and how these proposals compare versus past years? Well, you know, inflation is having an impact. I will say, 2021, the economics were, you know, lights out, good as it get. Certainly we've seen a little softening in commodity prices as we look into 2023 and we've seen inflation. You know, you kind of have to put things in context. As we look at the plans that have been laid in front of us in 2023, the economics on any normalized decade-long historical look are really, really strong. We have a lot of things to do. We've asked each one of our business units to kind of give us a small, medium, and large. You know, where small is maintenance, and then we look at various options and so that we can mix and match and form the best capital program we can. You know, we talked earlier about 2022 being, you know, largely underway when we formed Coterra. That's not the case with 2023. We truly do have options to construct the best program possible. You know, you heard me say in my opening remarks, we have services under contract that gives us flexibility. Because as we look at 2023. Boy, if anybody in this call can tell us what 2023 can look like, we'll get you to the front of the line here. You know, we've got commodity price uncertainty. We also have inflation uncertainty. We have world economic outlook that's uncertain and, you know, global demand. You know, I am not being trite when I say flexibility is coin of the realm. We will enter 2023 with services under our control that would allow us to accelerate or decelerate, and we'll have flexibility. Really, we're working this hard. One thing I can promise you is that 2023 will be a very profitable program, or we won't make the investments. Right now, as we model it, we're gonna have a lot of options within a very wide band of potential capital, you know, total capital and where we allocate it. You know, just look forward to coming out with some detail once we really make these commitments to our business units. As my follow-up, regarding your comments on the Harkey moving into development mode, it's clear that you're comfortable with the subsurface and well design. Having said that, could you speak to how the Harkey competes for capital versus the Upper Wolfcamp A? Well, it kind of depends where you are in the basin. The Harkey is excellent compared to the Wolfcamp. I mean, they're neck and neck. You know, of course, the Wolfcamp is. I mean, look, there's a lot of variability in Delaware Basin, so it's kinda hard to average. You know, if you had to choose between really great Wolfcamp A or Harkey, it'd be like asking which one of your kids you like the best. It's a really tough choice. It's a great color. Thanks for your time. Your next question is from David Deckelbaum of TD Cowen. Please go ahead. Your line is open. Thanks for taking my questions, Tom. Hi, David. Hi there. I wanted to ask maybe a point of clarification on the Marcellus, and I'm sorry you're getting a lot of questions on this today. I guess as it relates to when you first looked at the assets, during the M&A process or during the merger process, if you compare it to today, what was a lot of the write-downs more on the parent or child well size? Is this more of an indication that the parent wells are being more impacted as you do more in-field activity drilling, or is there just multiple variables that wouldn't necessarily describe the majority of the move? Well, you know, when you look at the Marcellus program, obviously like any shale basin, it over time gravitated to a higher percentage of child infill wells. You know, if you look at just the complexity, the makeup of the drilling programs over the last few years, you know, we're for the last number of years have been drilling a majority of infill wells. You know, to your question, I mean, a lot of it is of course driven by the behavior of infill wells. You know, we're doing a lot. We're looking at changing our spacing, as we've talked about in the past. We're also. You know, we had a really good technical meeting in Pittsburgh a couple weeks ago, and they're doing some great work revisiting our completions, and we think we may have some optimization by rethinking that. You know, I mean, it's driven by well performance, and well performance is mostly infill wells because that's been the complexion of our program. I appreciate that. Thanks, Tom. Maybe if I could just ask a quick follow-up. There was a mention, obviously, in your prepared remarks in the presentation about looking at long-term service contracts, but then obviously also maintaining flexibility on the view that perhaps that market might soften next year. I guess, are you in the midst now or of signing long-term agreements? And I guess when you think about a long-term agreement for a base level of activity, how long is the duration of those contracts? And I guess what would be the benefit of doing that? Is there a fear that you won't have the availability of quality crews going forward in a tight market, or is it really price-driven protection? Yeah. David Deckelbaum, this is Blake Sirgo. I'll take that one. You nailed it. Priority number one is securing premium rigs and crews. We have to have those to execute our capital programs, and the market's requiring a lot of long-term contracts to get that done right now. That's what's forcing that decision. Second, of course, is price. As Thomas Jorden mentioned, who knows what 2023 is gonna do? Price is a little tough to get our arms around. What we do is we leverage our longer term commitments in blocking up a whole bunch of work, and we use that to leverage flexibility on additional work, so that if we pick up or drop crews, we know they're available to us and some surety of price around what that'll be. It's just a combination of managing that portfolio. Sorry, just to clarify, are the terms longer than we would normally expect with a term contract? Are these multi-year agreements, or are this typically for 12 months? No, typically 12 months. Thank you, guys. Less. Your next question is from Doug Leggate at Bank of America. Please go ahead. Your line is open. Thank you. Good morning, everybody. Tom, thanks for taking my questions. Tom, I apologize for going back to the Upper and Lower Marcellus, but I wanted to ask a couple of technical issues to try and maybe connect the dots a little bit here. You talked about the Purcell being an effective frack barrier, but I think we're aware that there's some pinching out across the acreage, and I assume that the wells you tested were probably in the thickest part of the barrier, if you want to call it that. Can you walk us through how you see the risking across the acreage, and how it might inform your view of inventory depth today versus at the time of the acquisition? Yeah, Doug, as we map the Purcell, it is, we think, reasonably thick over almost all of our asset. You know, we're talking, you know, 40 ft, 50 ft, generally. We don't see an area in our asset where we would have heightened concern about the Purcell not being a frack barrier. If you zoom out and you look at the region outside of our asset, that statement's gonna change. The Purcell does thin, and there are areas around us where the Upper and Lower Marcellus behave as one continuous petroleum system. We don't think that's gonna be the case on our asset. You know, Doug, you know us well. I want to be very careful with how I answer that question. With our best technology right now, and we've got a fair number of tests where we've put tracers and looked at communication across that Purcell barrier. With our best information now, we have a high degree of confidence that that statement is true. As we look at the area, we think it's gonna be repeatable across the area. That is one thing that we will be testing as we look at additional Upper Marcellus wells. You know, I always want to be careful of getting ahead of ourselves on what we believe against what we know. I mean, based on all of our technical experience, we believe that Purcell is gonna be frac barrier, and all of our experiments today have confirmed that. We will update you. We feel very confident today in saying that the Upper Marcellus will be an independent petroleum system from the Lower and will be developed without significant interference. That's very clear, Tom. I appreciate that. I might be, you know, trying to peel the onion back in too much detail here, but my follow-up is also related to that. I'm just wondering if you could share what you've observed through your testing as it relates to how the pressure gradient has evolved across the Upper Marcellus. You know, your point about, you know, lack of communication between the two zones. Have you seen any shift as you started to, you know, any evidence, for example, as Chesapeake pointed out that, you know, co-development might be the right way forward because there is some communication? Or are you saying that, no, you don't believe that to be the case? Now, you know, different areas are gonna behave differently, and I don't wanna comment on another operator, but that comment doesn't surprise me. We see our area as somewhat unique in that Purcell and the thickness across our area. We think co-development would not be the right approach. In fact, we also think that the fact that we have that barrier really allows us to take more efficient use of our infrastructure because we have compression and field hydraulics. If we were required to co-develop, that would be a much more challenging, complex problem. The fact that we've got that Purcell frack barrier is really, I think, an important part of our economic development. We just think we're in a different area, Doug. Well, thanks, Tom, and we'll see you in a couple of weeks. Appreciate you taking my questions. Your next question is from Paul Cheng of Scotiabank. Please go ahead. Your line is open. Hi, that's Paul Cheng. Thomas Jordan, I want to go back into the M&A question. Can you give us some criteria or financial metrics that you would be looking at? Also that in an ideal world, what are geographic region or that oil or that gas asset you would be focused on that you don't already have any of those specific target? Well, yeah. Thank you, Paul. Yeah, when it comes to M&A, you know, first and foremost, we would like to find some things that compete for capital in a reasonable timeframe. You know, you wake up every morning and rethink every problem, at least in a changing world. If you don't, you're making a mistake. It's kinda tough for us to just say flat out, "We will not consider anything if it doesn't have the kind of returns that are currently in our inventory." Because if that's our criteria, we're done. You know, there's very little out there that competes with our inventory. You know, we wanna think decades in the future and find assets that we think are more valuable in our hands than the current owner, which is another way of saying that we think we might be able to buy it right and create value through that. That's a really, really high bar. You know, we remain opportunistic, but you know, we're fortunately, because of the depth of our inventory, under no pressure here. You know, as far as your second part of the question to geography, You know, we're a multi-basin company. We're a multi-commodity company. We know how to play and how to manage a company that's geographically spread out. In fact, we think it's one of the strengths of Coterra, and we think over time the marketplace will see how that strength produces more consistent results over time. But there are some things that we'd want to be careful of. There are some operating environments that are more difficult. There are some areas that are more politically difficult. You know, we would be selective in terms of what new areas we would look at. You know, we know how to manage a multi-basin company, and that wouldn't deter us if it checked all the boxes. That said, I want to just finish with a statement I made. Because of the depth and quality of our inventory, we have the luxury of really forcing ourselves to have a high bar and make sure that anything we look at is in the best interest of the owners. Hey, Tom, do you have a preference between oil or gas, or it doesn't really matter? Also that from a organization capability limit, since you are still in the process of integrating, do you think that you already have done enough on the integration that you can take on a substantially new asset or that you may take another six to nine months before you reach that comfort state? Well, I mean, these are a lot of hypotheticals here because, you know, the M&A question is always one that, you know, it's an optionality. It's not necessarily something that, you know, we have specifics to talk about. You know, the integration is going very, very well. Our teams, as I said in my opening remarks, are really coming together. The fun thing from my standpoint is that, there's really an organic cooperation that's leveraging the great ideas and experience of all of our organization as they get to know one another. There's a lot of power in that. You know, good ideas are not regionally constrained when you have a lot of cross-company collaboration. What was the first part? Do you have a preference? Oh, oil versus gas? Yeah. between oil or gas? Yeah. Or it doesn't ma- No. You know, our preference is generating profits and profitable investments. We do like a commodity mix just because of the swing in the commodity that was part of the thesis in forming Coterra. You know, we're roughly balanced between liquids and natural gas on a revenue standpoint. We would consider any asset, any commodity mix if we thought it made Coterra a stronger company. We're not in the interest of picking commodities. We're in the interest of picking profitability. A final question on Anadarko. I think that you guys have been evaluating the asset, and at this point, is there anything you can share that what you think will be the future for that asset? Whether you will start increasing your activity level for next year or it's going to take some more time? Thank you. Well, you know, we're not prepared to talk about 2023 capital on this call in any great detail. I will share, you know, we've got a couple of projects flowing back in the Anadarko right now, and we're watching them with great interest. Look forward to updating you on them. You know, although we're very encouraged by what we see, we've been around this business long enough to know, particularly on projects that have infill potential, you want to watch things over some months before you call it. You know, we're flowing a couple of projects back that look pretty interesting to us. Thank you. Your next question is from Noel Parks of Tuohy Brothers. Please go ahead. Your line is open. Morning. Morning, Noel. I realize it's a little early in the process, but as you head into year-end and given what you've told us about looking at reserves in itself, can you comment a bit on operating cost assumptions and how those, I guess just what you're thinking of long term? You know, I don't know if any of us expected we would see such a sharp increase in the tightness in the service environment. So if you could just comment on the cost component as you look ahead. Yeah. You know, we're in the fourth quarter, as we finish out our normal reserve process, we'll be updating lease operating expenses or LOE. We do expect LOE to increase, but, you know, there's not a one-for-one connection between LOE and reserves, and that's particularly true in the Marcellus. I mean, those operating costs are so low that, you know, we're kind of at 50-year reserve life, and you really find that pricing and LOE doesn't really have much of an impact. That's not true elsewhere. You know, as part of our fourth quarter process, and we do, as I said earlier, wanna dot the I's, cross the T's, and although we talked about a range, we have some work to do. One of those is around LOE, one of the items. We don't see that as a certainly not a item that will have meaningful impact on Marcellus reserves. I mean, we'll have to do the process, but I don't anticipate updating LOE having much of an impact on our end of year. Great. Thanks for the clarification. Like, turning again to Anadarko for a minute. Just in general terms, it is interesting that even among some of the basins that are maturing, you know, further along in their development in the Permian, for instance, we've seen a fair amount of M&A and consolidation activity this year. I'm just wondering if not so much in the Anadarko, just wondering if you think that still lies ahead or whether a piece of that is just as an industry, you know, the capital and sort of the technological advances aren't necessarily being manifested in that play the way they are, you know, more aggressively in others. You're talking specifically to the Anadarko? Yes. Yeah. Well, you know, one of the interesting things in our business is you do have single basin players. Often technology, even though you think, well, it's known by all, technological adoptions and innovations sometimes don't spread like wildfire from basin to basin. You can occasionally have disconnection. You know, if we had more time, I could offer a lot of examples of that that I've seen in my career. You know, my experience and observation is there's some pretty smart players in the Anadarko. A lot of these private equity companies are fairly innovative. A lot of these teams came out of larger shops and certainly were schooled in understanding the full range of available technologies. I don't know if I would share the opinion that the Anadarko is behind on technology. I'd love to take that offline, but I just don't see it that way. Great. Thanks a lot. There are no further questions at this time. I will now turn the call over to Thomas Jorden for closing remarks. Well, listen, I wanna thank everybody for your great questions. We delved into some good issues and really do look forward to continuing to generate the type of outstanding results we did in the third quarter. We're very confident that Coterra is lined up to continue to have a landscape of just outstanding returns, good capital returns, great discipline, and also look forward to discussing our 2023 capital program next time we convene. Thank you all very much. This concludes today's conference call. Thank you for your participation. You may now disconnect.